Penn Virginia Corporation Announces Third Quarter 2011 Results and Provides Operational Update

RADNOR, Pa.--(BUSINESS WIRE)--

Penn Virginia Corporation PVA today reported financial and operational results for the three months ended September 30, 2011 and provided an update of 2011 guidance.

Third Quarter 2011 Highlights

Third quarter 2011 results, as compared to third quarter 2010 results, were as follows:

• Product revenues from the sale of natural gas, crude oil and natural gas liquids (NGLs) of $82.0 million, or $6.86 per thousand cubic feet of natural gas equivalent (Mcfe), an increase of 20 percent as compared to $68.3 million, or $5.15 per Mcfe
• Oil and NGL revenues of $47.8 million, or 58 percent of product revenues, an increase of 129 percent as compared to $20.9 million, or 31 percent of product revenues
• Gross operating margin, defined as product revenues less direct cash operating expenses, of $4.72 per Mcfe, an increase of $1.83 per Mcfe, or 63 percent, as compared to $2.89 per Mcfe
• Operating loss of $9.0 million, a decrease of $44.1 million as compared to a loss of $53.1 million
• Adjusted EBITDAX, a non-GAAP (generally accepted accounting principles) measure, of $65.7 million, an increase of $19.8 million, or 43 percent, as compared to $45.9 million
• Net loss of $6.7 million, or $0.15 per diluted share, a decrease of $23.5 million as compared to a loss of $30.2 million, or $0.66 per diluted share
• Adjusted net loss, a non-GAAP measure, of $6.7 million, or $0.15 per diluted share, a decrease of $7.2 million as compared to a loss of $13.9 million, or $0.31 per diluted share
• Oil and NGL production of 649 thousand barrels, or 33 percent of total equivalent production, an increase of 63 percent as compared to 399 thousand barrels, or 18 percent of total equivalent production, primarily as a result of our drilling activity in the Eagle Ford Shale
• Production of 11.9 billion cubic feet of natural gas equivalent (Bcfe), or 129.9 million cubic feet of natural gas equivalent (MMcfe) per day, a decrease of ten percent as compared to 13.3 Bcfe, or 144.3 MMcfe per day, primarily as a result of a 26 percent decrease in natural gas production due to our planned shift away from natural gas drilling since mid-2010, partially offset by the 63 percent increase in oil and NGL production

Definitions of non-GAAP financial measures and reconciliations of these non-GAAP financial measures to GAAP-based measures appear on page nine of this release.

Additional operational highlights included:

• Eight (6.6 net) Eagle Ford Shale wells have been completed and turned in line since our last report in August 2011, bringing the total to 20 (16.7 net) Eagle Ford Shale wells to date, with an average peak gross production rate of 1,012 barrels of oil equivalent (BOE) per day (BOEPD) per well
  • To date, 17 wells have had a 30-day average gross production rate of 688 BOEPD per well
• Four rigs are currently drilling the 25^th through 28^th Eagle Ford Shale wells, with four wells waiting on completion
• Approximately 2,000 net acres were added to the Eagle Ford Shale play in the third quarter of 2011, bringing total acreage to approximately 17,900 (14,700 net) acres in Gonzales County, Texas with approximately 140 identified well locations

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, “Our greatly improved third quarter financial results reflected our transition to and focus on oil drilling opportunities. Oil and liquids production increased 63 percent over the prior year quarter and comprised 33 percent of third quarter production. Oil and liquids revenues increased 129 percent over the prior year period and comprised 58 percent of product revenues, resulting in a 63 percent improvement in our gross operating margin per Mcfe of production. In the fourth quarter of 2011, we expect oil and liquids to comprise approximately 42 to 44 percent of production.

“Our improved third quarter financial results were driven primarily by our oily Eagle Ford Shale play. We are currently operating four rigs in the Eagle Ford Shale and expect to exit 2011 with three rigs drilling in this play. Altogether, our results in the Eagle Ford Shale have been strong, and we continue to review leasing and acquisition opportunities to expand our drilling inventory in this play.”

Third Quarter 2011 Financial and Operational Results

Overview of Financial Results

The $9.0 million operating loss was $44.1 million lower than the $53.1 million loss in the prior year quarter primarily due to a $35.1 million decrease in impairment expense (none in the current year quarter), a $26.9 million increase in oil and liquids revenues, a $4.3 million decrease in total direct operating expenses and a $2.7 million decrease in exploration expense. The effect of these items was partially offset by a $13.3 million decrease in natural gas revenues and a $12.1 million increase in DD&A expense. Oil and NGL revenues were $47.8 million in the third quarter of 2011, 129 percent higher than the $20.9 million in the prior year quarter and 38 percent higher than the $34.7 million in the second quarter of 2011. Oil and NGL revenues were 58 percent of product revenues in the third quarter of 2011, as compared to 31 percent in the prior year quarter and 48 percent in the second quarter of 2011.

Pricing

Our third quarter 2011 realized oil price was $87.03 per barrel, 23 percent higher than the $70.97 per barrel price in the third quarter of 2010 and 12 percent lower than the $98.45 per barrel price in the second quarter of 2011. Our third quarter 2011 realized NGL price was $48.00 per barrel, 35 percent higher than the $35.57 per barrel price in the third quarter of 2010 and eight percent lower than the $52.04 per barrel price in the second quarter of 2011. Our third quarter 2011 realized natural gas price was $4.24 per thousand cubic feet (Mcf), three percent lower than the $4.36 per Mcf price in the third quarter of 2010 and two percent lower than the $4.32 per Mcf price in the second quarter of 2011. Adjusting for oil and gas hedges, our third quarter 2011 effective natural gas price was $4.87 per Mcf and our effective oil price was $88.28 per barrel, or increases of $0.63 per Mcf and $1.25 per barrel over the realized prices.

Production

As shown in the table below, production in the third quarter of 2011 was approximately 11.9 Bcfe, or 129.9 MMcfe per day, a ten percent decrease as compared to 13.3 Bcfe, or 144.3 MMcfe per day, in the prior year quarter and a two percent increase from 11.7 Bcfe, or 128.6 MMcfe per day, in the second quarter of 2011. As a percentage of total equivalent production, oil and NGL volumes were 33 percent in the third quarter of 2011, as compared to 18 percent in the prior year quarter, 24 percent in the second quarter of 2011 and 20 percent in the first quarter of 2011.

				Total and Daily Equivalent Production for the Three Months Ended
Region / Play Type				Sept. 30, 2011				Sept. 30, 2010				June 30, 2011				Sept. 30, 2011				Sept. 30, 2010				June 30, 2011
				(in Bcfe)												(in MMcfe per day)
Texas				4.9				4.0				4.2				53.3				43.7				46.4
Cotton Valley				1.8				1.7				2.1				19.9				18.0				22.7
Haynesville Shale				1.0				2.4				1.2				11.1				25.7				13.1
Eagle Ford / Other(1)				2.1				---				1.0				22.4				---				10.6
Appalachia				2.3				2.7				2.3				24.7				29.4				24.7
Mid-Continent				3.2				4.5				3.5				34.8				48.6				38.8
Granite Wash				2.7				3.5				2.9				29.7				38.1				31.6
Other(2)				0.5				1.0				0.7				5.1				10.5				7.2
Mississippi				1.6				2.1				1.7				17.0				22.6				18.6
Totals				11.9				13.3				11.7				129.9				144.3				128.6

(1)		Initial production from the Eagle Ford Shale commenced in February 2011.
(2)		Includes properties, primarily in the Arkoma Basin, sold in August 2011.
Note - Numbers may not add due to rounding.

The year-over-year production decrease was due to a 2.8 Bcfe, or 26 percent, decrease in natural gas production resulting from our planned shift away from natural gas drilling since mid-2010 and the subsequent natural production declines. The decrease in natural gas production was partially offset by a 1.5 Bcfe, or 63 percent, increase in oil and NGL production primarily associated with our drilling activity in the Eagle Ford Shale and increased NGL volumes from the Granite Wash. The sequential quarterly increase in production was primarily attributable to higher oil and NGL volumes from the Eagle Ford Shale, partially offset by natural gas production declines, the August 2011 sale of Arkoma Basin properties and lower NGL production in the Granite Wash as a result of a fire at a third-party processing plant, which has reduced NGL sales volumes since July 2011.

Operating Expenses

As discussed below, third quarter 2011 total direct operating expenses decreased $4.3 million, or approximately 14 percent, to $25.6 million, or $2.14 per Mcfe produced, as compared to $29.9 million, or $2.25 per Mcfe produced, in the third quarter of 2010 and $28.8 million, or $2.47 per Mcfe produced, in the second quarter of 2011.

• Lease operating expenses decreased by $0.8 million, or nine percent, to $8.5 million, or $0.71 per Mcfe produced, from $9.3 million, or $0.70 per Mcfe produced, in the prior year quarter due to lower production volumes as well as lower maintenance, compression and workover costs, partially offset by higher environmental, water disposal and employee-related costs. The unit cost increased slightly due to lower production volumes
• Gathering, processing and transportation expenses decreased by $0.6 million, or 19 percent, to $3.0 million, or $0.25 per Mcfe produced, from $3.6 million, or $0.27 per Mcfe produced, in the prior year quarter resulting from lower production volumes, partially offset by higher processing costs associated with higher NGL production
• Production and ad valorem taxes decreased 36 percent to $3.4 million, or 4.1 percent of product revenues, from $5.3 million, or 7.8 percent of product revenues, in the prior year quarter resulting primarily from a property tax recovery in Appalachia, as well as lower production volumes
• General and administrative (G&A) expenses, excluding share-based compensation, decreased by $0.9 million, or eight percent, to $10.8 million, or $0.91 per Mcfe produced, from $11.7 million, or $0.88 per Mcfe produced, in the prior year quarter. This decrease reflects a $1.7 million reduction in recurring G&A expenses resulting from lower employee headcount and lower support costs following our 2010 restructuring actions, partially offset by a $0.8 million increase in restructuring costs following the sale of our Arkoma Basin assets in August 2011. The unit cost increased slightly due to lower production volumes

Exploration expense decreased $2.7 million to approximately $19.3 million in the third quarter of 2011 from $22.0 million in the prior year quarter. The decrease was primarily due to a $9.3 million decrease in dry hole costs and a $1.2 million decrease in geological and geophysical costs, partially offset by $4.8 million of rig-related charges incurred in the third quarter of 2011 in connection with the temporary suspension of our exploratory drilling program in the Marcellus Shale and a $3.1 million increase in amortization of unproved leasehold properties related to significant acquisitions during 2010.

DD&A expense increased by $12.1 million, or 36 percent, to $45.3 million, or $3.80 per Mcfe produced, in the third quarter of 2011 from $33.2 million, or $2.50 per Mcfe produced, in the prior year quarter, primarily due to higher DD&A costs attributable to our Eagle Ford Shale oil wells, which can be typical for this and other oily plays, partially offset by lower production volumes.

Operational Update

Eagle Ford Shale

During the third quarter of 2011, we drilled 10 (8.3 net) operated wells in the Eagle Ford Shale, all of which were successful. We currently have four rigs drilling our 25^th through 28^th wells, four wells that are waiting on completion (WOC) and 20 (16.7 net) wells that are producing. As shown in the table below, our initial 20 wells in the Eagle Ford Shale have had an average peak gross production rate of 1,012 BOEPD per well (688 BOEPD 30-day average per well for 17 of these wells).⁽³⁾

									Cumulative Gross Production(3)						Peak Gross Daily Production Rates(3)						30-Day Average Gross Daily Production Rates(3)
Well Name			Lateral Length			Frac Stages			Equivalent Production			Days On Line			Oil Rate			Equivalent Rate			Oil Rate			Equivalent Rate
			feet						BOE						BOPD			BOEPD			BOPD			BOEPD
Previously Reported On-Line Wells
Gardner #1H			4,792			16			129,946			275			1,084			1,247			732			881
Hawn Holt #1H			4,053			15			73,952			182			759			837			606			668
Hawn Holt #2H			4,476			17			71,524			149			869			986			668			728
Hawn Holt #4H			4,106			14			45,281			179			534			582			357			394
Hawn Holt #6H			4,166			17			46,111			150			670			711			342			370
Hawn Holt #9H			4,453			18			90,538			145			1,652			1,877			1,044			1,153
Hawn Holt #10H			3,913			16			62,836			121			1,080			1,188			771			839
Hawn Holt #3H			3,800			15			41,232			114			607			651			478			522
Hawn Holt #5H			3,950			16			32,735			113			474			528			321			349
Munson Ranch #1H			4,163			17			90,609			104			1,755			1,921			1,207			1,315
Munson Ranch #3H			3,953			16			66,241			103			1,448			1,538			1,007			1,092
Hawn Holt #11H			3,931			16			51,640			99			1,120			1,190			786			860
New On-Line Wells
Hawn Holt #7H			4,345			18			27,960			68			730			798			493			541
Dickson Allen #1H			3,953			15			20,305			67			465			508			358			393
Hawn Holt #12H			3,320			18			33,255			60			1,458			1,495			619			668
Cannonade Ranch #1H			4,403			18			14,361			51			377			403			255			274
Hawn Holt #13H			2,805			11			25,877			47			1,347			1,399			585			650
Hawn Holt #15H			4,153			17			23,388			28			1,191			1,298			---			---
Dickson Allen #2H			3,853			16			9,120			20			552			601			---			---
Hawn Holt #8H			4,203			17			6,383			19			427			492			---			---
Averages			4,040			16									930			1,012			625			688
Maximums			4,792			18									1,755			1,921			1,207			1,315
Minimums			2,805			11									377			403			255			274
Other Wells
Cannonade Ranch #3H			WOC
Gardner #2H			WOC
Munson Ranch #2H			WOC
Schaefer #1H			WOC
Munson Ranch #4H			Drilling
Munson Ranch #6H			Drilling
Rock Creek Ranch #1H			Drilling
Schaefer #2H			Drilling

(3)		Wellhead rates only; the natural gas associated with these wells is yielding approximately 145 barrels of NGLs per million cubic feet (MMcf).

In the third quarter of 2011, we increased our net Eagle Ford Shale leasehold position by approximately 2,000 net acres to 14,700 net acres. Thus far in 2011, we have added 7,300 net acres in Gonzales County for approximately $27 million. We have identified approximately 140 horizontal well locations on our current acreage position of approximately 17,900 gross acres, including the 24 wells that have been drilled. Our full-year 2011 guidance anticipates up to 33 (27.5 net) wells, with up to 12 (10.0 net) wells to be drilled during the fourth quarter of 2011. We continue efforts to expand our Eagle Ford Shale position in Gonzales County and other prospective areas in the play through additional leasing and selective acquisitions.

Granite Wash

During the third quarter of 2011, three (1.1 net) non-operated Granite Wash wells were drilled in the Mid-Continent, of which PVA went non-consent on the completion of one (0.05 net) well. Our full-year 2011 guidance includes up to 20 (8.7 net) wells, with up to four (1.2 net) wells to be drilled during the fourth quarter of 2011.

Capital Expenditures

During the third quarter of 2011, oil and gas capital expenditures were approximately $114 million, as compared to $147 million in the third quarter of 2010 and $105 million in the second quarter of 2011, consisting of:

• $102 million for drilling and completion activities, including 13 (9.5 net) wells, 12 (9.4 net) of which were successful and one (0.05 net) of which PVA went non-consent on the completion
• $6 million for seismic, pipeline, gathering and facilities
• $6 million for leasehold acquisitions and other

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of September 30, 2011, we had total debt with a carrying value of $613 million ($620 million aggregate principal amount), consisting of $293 million of 10.375 percent senior unsecured notes due 2016, $300 million principal amount of 7.25 percent senior unsecured notes due 2019, $5 million principal amount of 4.5 percent convertible senior subordinated notes due 2012 and $15 million of borrowings under our revolving credit facility. Net of cash and equivalents of approximately $4 million, our indebtedness at September 30, 2011 was approximately $609 million, or 38 percent of book capitalization.

In August 2011, we announced an amended and restated senior secured revolving credit facility with a five-year maturity, a $300 million commitment amount and an accordion feature to expand commitment amounts by up to $300 million, with the total commitments not to exceed the borrowing base. The current borrowing base of $380 million, which has been adjusted for the impact of the recent sale of our Arkoma Basin assets and was recently reaffirmed, is subject to redetermination on a semi-annual basis. As of September 30, 2011, our available borrowing capacity under the revolver, as reduced by outstanding borrowings and letters of credit of $16.4 million, was approximately $284 million, which, together with cash and equivalents, comprised financial liquidity of approximately $288 million.

Interest expense increased to $14.2 million in the third quarter of 2011 from $13.2 million in the third quarter of 2010 due to higher average levels of debt outstanding, partially offset by lower effective interest rates.

During the third quarter of 2011, derivatives income was $11.5 million, as compared to derivatives income of $15.1 million in the prior year quarter. Third quarter 2011 cash settlements of derivatives resulted in net cash receipts of $8.5 million, as compared to $6.8 million of net cash receipts in the prior year quarter.

Fourth Quarter 2011 Guidance Update

Fourth quarter 2011 guidance highlights are as follows:

• Fourth quarter production guidance of 12.2 to 12.7 Bcfe, 32 to 33 percent of which is expected to be crude oil and 10 to 11 percent of which is expected to be NGLs
  • Full-year 2011 production, including fourth quarter guidance, is expected to be 48.0 to 48.5 Bcfe, a decrease of 0.5 to 2.0 Bcfe from previous guidance of 48.5 to 50.5 Bcfe, primarily due to delays in completions in the Eagle Ford Shale and the Granite Wash (non-operated), reduced NGL recoveries in the Granite Wash during the second half of 2011 and delays in initial production by the Marcellus Shale horizontal wells which were drilled earlier in 2011
• Fourth quarter capital expenditures guidance of $110 to $120 million
  • Full-year 2011 capital expenditures, including fourth quarter guidance, is expected to be $433 to $443 million, an increase of between $63 and $73 million from previous guidance of $360 to $380 million, primarily due to increased drilling, completion and other costs for recent Eagle Ford Shale wells

Please see the Guidance Table included in this release for guidance estimates for full-year 2011. These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision as our operating environment changes.

Third Quarter 2011 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss third quarter 2011 financial and operational results, is scheduled for Thursday, November 3, 2011 at 10:00 a.m. ET. Prepared remarks by H. Baird Whitehead, President and Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing 1-866-630-9986 five to ten minutes before the scheduled start of the conference call (use the passcode 7085147), or via webcast by logging on to our website, www.pennvirginia.com, at least 15 minutes prior to the scheduled start of the call to download and install any necessary audio software. A telephonic replay will be available for two weeks beginning approximately 24 hours after the call. The replay can be accessed by dialing toll free 888-203-1112 (international: 719-457-0820) and using the replay code 7085147. In addition, an on-demand replay of the webcast will also be available for two weeks at our website beginning approximately 24 hours after the webcast.

Penn Virginia Corporation PVA is an independent oil and gas company engaged primarily in the development, exploration and production of natural gas and oil in various domestic onshore regions including Texas, Appalachia, the Mid-Continent and Mississippi. For more information, please visit our website at www.pennvirginia.com.

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: the volatility of commodity prices for natural gas, natural gas liquids and oil; our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of natural gas, natural gas liquids and oil; reductions in the borrowing base under our revolving credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable costs and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves; drilling and operating risks; our ability to compete effectively against other independent and major oil and natural gas companies; uncertainties related to expected benefits from acquisitions of oil and natural gas properties; environmental liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to general domestic and international economic and political conditions; and other risks set forth in our filings with the Securities and Exchange Commission (SEC).

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management's views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - unaudited
(in thousands, except per share data)
			Three months ended										Nine months ended
			September 30,										September 30,
			2011					2010					2011					2010
Revenues
Natural gas			$	34,171				$	47,476				$	113,660				$	134,283
Crude oil				37,147					13,396					75,278					38,117
Natural gas liquids (NGLs)				10,676					7,459					33,758					14,987
Total product revenues				81,994					68,331					222,696					187,387
Gain on sales of property and equipment				71					280					523					616
Other				1,288					342					2,335					2,116
Total revenues				83,353					68,953					225,554					190,119
Operating Expenses
Lease operating				8,458					9,256					29,522					27,148
Gathering, processing and transportation				2,952					3,625					11,261					10,165
Production and ad valorem taxes				3,391					5,309					11,289					12,684
General and administrative (excluding share-based compensation) (a)				10,815					11,734					33,312					37,897
Total direct operating expenses				25,616					29,924					85,384					87,894
Share-based compensation (b)				1,820					1,711					5,629					6,400
Exploration				19,303					22,020					68,219					37,590
Depreciation, depletion and amortization				45,345					33,224					113,224					95,358
Impairments (c)				-					35,127					71,071					36,251
Other				300					-					300					465
Total operating expenses				92,384					122,006					343,827					263,958
Operating loss				(9,031	)				(53,053	)				(118,273	)				(73,839	)
Other income (expense)
Interest expense				(14,206	)				(13,198	)				(41,833	)				(40,190	)
Loss on extinguishment of debt (d)				(1,165	)				-					(25,403	)				-
Derivatives				11,498					15,113					19,827					44,410
Other				61					342					334					2,105
Loss from continuing operations before income taxes				(12,843	)				(50,796	)				(165,348	)				(67,514	)
Income tax benefit				6,125					20,637					60,372					27,024
Loss from continuing operations				(6,718	)				(30,159	)				(104,976	)				(40,490	)
Income from discontinued operations, net of tax				-					-					-					33,482
Gain on sale of discontinued operations, net of tax				-					-					-					49,612
Net income (loss)				(6,718	)				(30,159	)				(104,976	)				42,604
Less net income attributable to noncontrolling interests in discontinued operations				-					-					-					(28,090	)
Income (loss) attributable to PVA			$	(6,718	)			$	(30,159	)			$	(104,976	)			$	14,514
Income (loss) per share attributable to PVA - Basic
Continuing operations			$	(0.15	)			$	(0.66	)			$	(2.29	)			$	(0.89	)
Discontinued operations				-					-					-					0.12
Gain on sale of discontinued operations				-					-					-					1.09
Net income (loss) attributable to PVA			$	(0.15	)			$	(0.66	)			$	(2.29	)			$	0.32
Income (loss) per share attributable to PVA - Diluted
Continuing operations			$	(0.15	)			$	(0.66	)			$	(2.29	)			$	(0.89	)
Discontinued operations				-					-					-					0.12
Gain on sale of discontinued operations				-					-					-					1.09
Net income (loss) attributable to PVA			$	(0.15	)			$	(0.66	)			$	(2.29	)			$	0.32
Weighted average shares outstanding, basic				45,817					45,591					45,758					45,534
Weighted average shares outstanding, diluted				45,817					45,591					45,758					45,733
			Three months ended										Nine months ended
			September 30,										September 30,
			2011					2010					2011					2010
Production
Natural gas (MMcf)				8,051					10,890					26,646					28,590
Crude oil (MBbls)				427					189					833					522
NGLs (MBbls)				222					210					695					395
Total natural gas, crude oil and NGL production (MMcfe)				11,947					13,280					35,817					34,093
Prices
Natural gas ($ per Mcf)			$	4.24				$	4.36				$	4.27				$	4.70
Crude oil ($ per Bbl)			$	87.03				$	70.97				$	90.33				$	72.96
NGLs ($ per Bbl)			$	48.00				$	35.57				$	48.56				$	37.96
Prices - Adjusted for derivative settlements
Natural gas ($ per Mcf)			$	4.87				$	5.05				$	4.88				$	5.59
Crude oil ($ per Bbl)			$	88.28				$	70.62				$	90.55				$	72.64
NGLs ($ per Bbl)			$	48.00				$	35.57				$	48.56				$	37.96

(a) Includes restructuring costs of approximately $1.5 million and $1.6 million for the three month periods and $0.8 million and $6.4 million for the nine month periods ended September 30, 2011 and 2010, respectively.

(b) Our share-based compensation expense includes our stock option expense and the amortization of common stock, deferred stock, restricted stock and restricted stock unit awards related to employee and director compensation.

(c) Impairment of $71.1 million in the nine months ended September 30, 2011 relates to non-core, primarily Arkoma Basin properties sold in August 2011.

(d) Attributable primarily to the repurchase in April 2011 of approximately 98% of our 4.5% Convertible Senior Subordinated Notes due 2012.

PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited
(in thousands)
													As of
													September 30,					December 31,
													2011					2010
Assets
Current assets													$	101,855				$	214,340
Net property and equipment														1,752,261					1,705,584
Other assets														22,891					24,676
Total assets													$	1,877,007				$	1,944,600
Liabilities and shareholders' equity
Current liabilities													$	104,922				$	106,994
Revolving credit facility														15,000					-
Senior notes due 2016														293,281					292,487
Senior notes due 2019														300,000					-
Convertible notes due 2012														4,702					214,049
Other liabilities and deferred income taxes														284,739					350,794
Total shareholders' equity														874,363					980,276
Total liabilities and shareholders' equity													$	1,877,007				$	1,944,600
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
			Three months ended										Nine months ended
			September 30,										September 30,
			2011					2010					2011					2010
Cash flows from operating activities
Net income (loss)			$	(6,718	)			$	(30,159	)			$	(104,976	)			$	42,604
Adjustments to reconcile net income (loss) to net cash provided by operating activities from continuing operations:
Income from discontinued operations before income taxes				-					-					-					(36,832	)
Gain on sale of discontinued operations before income taxes				-					-					-					(84,740	)
Non-cash portion of loss on extinguishment of debt				634					-					22,456					-
Depreciation, depletion and amortization				45,345					33,224					113,224					95,358
Impairments				-					35,127					71,071					36,251
Derivative contracts:
Net (gains) losses				(11,498	)				(15,113	)				(19,827	)				(44,410	)
Cash settlements				8,527					6,803					20,302					24,287
Deferred income tax benefit				(6,125	)				13,882					(60,372	)				6,149
Loss (gain) on the sale of property and equipment, net				229					(280	)				(223	)				(151	)
Dry hole and unproved leasehold expense				11,376					16,983					52,457					26,501
Non-cash interest expense				1,062					2,869					5,812					9,089
Share-based compensation				1,820					1,711					5,629					6,400
Other, net				(40	)				121					225					(341	)
Changes in operating assets and liabilities				(5,207	)				(41,962	)				(2,614	)				(11,290	)
Net cash provided by operating activities from continuing operations				39,405					23,206					103,164					68,875
Cash flows from investing activities
Capital expenditures - property and equipment				(107,193	)				(145,629	)				(318,274	)				(313,710	)
Proceeds from the sale of PVG units, net (a)				-					-					-					139,120
Proceeds from the sale of property, plant and equipment, net				30,381					1,895					31,077					25,172
Other, net				-					-					100					1,192
Net cash (used in) provided by investing activities for continuing operations				(76,812	)				(143,734	)				(287,097	)				(148,226	)
Cash flows from financing activities
Dividends paid				(2,580	)				(2,569	)				(7,736	)				(7,700	)
Proceeds from revolving credit facility borrowings				30,000					-					30,000					-
Repayment of revolving credit facility borrowings				(15,000	)				-					(15,000	)				-
Proceeds from the issuance of Senior Notes due 2019				-					-					300,000					-
Repurchase of Convertible Notes				-					-					(232,963	)				-
Debt issuance costs paid				(2,291	)				-					(8,850	)				-
Proceeds from the sale of PVG units, net (a)				-					-					-					199,125
Distributions received from discontinued operations				-					-					-					11,218
Other, net				174					299					1,148					2,143
Net cash provided by financing activities from continuing operations				10,303					(2,270	)				66,599					204,786
Cash flows from discontinued operations
Net cash provided by operating activities				-					-					-					77,759
Net cash used in investing activities				-					-					-					(18,112	)
Net cash used in financing activities				-					-					-					(59,647	)
Net cash provided by discontinued operations				-					-					-					-
Net increase (decrease) in cash and cash equivalents				(27,104	)				(122,798	)				(117,334	)				125,435
Cash and cash equivalents - beginning of period				30,681					327,250					120,911					79,017
Cash and cash equivalents - end of period			$	3,577				$	204,452				$	3,577				$	204,452
Supplemental disclosures of cash paid for:
Interest (net of amounts capitalized)			$	(2,417	)			$	1,671				$	17,288				$	22,646
Income taxes (net of refunds received)			$	529				$	22,018				$	433				$	25,168

(a) Net proceeds from the sale of Penn Virginia GP Holdings, L.P. (PVG) units included in investing activities is attributable to the sale of the final tranche of PVG units, which resulted in the loss of control and deconsolidation of PVG from our financial statements. Net proceeds from the sale of PVG units included in financing activities represents proceeds received from sales of our ownership interests in PVG while we still maintained control of PVG.

PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
			Three months ended										Nine months ended
			September 30,										September 30,
			2011					2010					2011					2010
Reconciliation of GAAP "Net Income (loss) attributable to PVA" to Non-GAAP "Net Income (loss) attributable to PVA, as adjusted"
Net income (loss) attributable to PVA			$	(6,718	)			$	(30,159	)			$	(104,976	)			$	14,514
Adjustments for derivatives:
Net gains included in net income (loss)				(11,498	)				(15,113	)				(19,827	)				(44,410	)
Cash settlements				8,527					6,803					20,302					24,287
Adjustment for impairments				-					35,127					71,071					36,251
Adjustment for restructuring costs				1,553					787					1,623					6,434
Adjustment for net loss (gain) on sale of assets				229					(280	)				(223	)				(151	)
Adjustment for loss on extinguishment of debt				1,165					-					25,403					-
Adjustment for gain on sale of discontinued operations				-					-					-					(84,740	)
Impact of adjustments on income taxes				11					(11,101	)				(35,909	)				26,157
			$	(6,731	)			$	(13,936	)			$	(42,536	)			$	(21,658	)
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards, net of taxes				-					-					-					(28	)
Net loss attributable to PVA, as adjusted (a)			$	(6,731	)			$	(13,936	)			$	(42,536	)			$	(21,686	)
Net loss attributable to PVA, as adjusted, per share, diluted			$	(0.15	)			$	(0.31	)			$	(0.93	)			$	(0.47	)
Reconciliation of GAAP "Net income (loss) from continuing operations" to Non-GAAP "Adjusted EBITDAX"
Net loss from continuing operations			$	(6,718	)			$	(30,159	)			$	(104,976	)			$	(40,490	)
Income tax benefit				(6,125	)				(20,637	)				(60,372	)				(27,024	)
Interest expense				14,206					13,198					41,833					40,190
Depreciation, depletion and amortization expense				45,345					33,224					113,224					95,358
Exploration expense				19,303					22,020					68,219					37,590
Share-based compensation expense				1,820					1,711					5,629					6,400
EBITDAX				67,831					19,357					63,557					112,024
Adjustments for derivatives:
Net gains included in net income (loss)				(11,498	)				(15,113	)				(19,827	)				(44,410	)
Cash settlements				8,527					6,803					20,302					24,287
Adjustment for impairments				-					35,127					71,071					36,251
Adjustment for net loss (gain) on sale of assets				229					(280	)				(223	)				(151	)
Adjustment for non-cash portion of loss on extinguishment of debt				634					-					22,456					-
Adjustment for other non-cash items				-					-					-					(1,238	)
Adjusted EBITDAX (b)			$	65,723				$	45,894				$	157,336				$	126,763

(a) Net income (loss) attributable to PVA, as adjusted, represents net income (loss) attributable to PVA adjusted to exclude the effects of non-cash changes in the fair value of derivatives, impairments, restructuring costs, net gains and losses on the sale of assets, loss on the extinguishment of debt, gain on sale of discontinued operations and net income of Penn Virginia Resource Partners, L.P. (PVR) allocated to unvested PVR restricted units awarded as equity compensation that are held until vesting. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Net income (loss) attributable to PVA, as adjusted, is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income (loss) attributable to PVA.

(b) Adjusted EBITDAX represents net income (loss) from continuing operations before income tax expense or benefit, interest expense, depreciation, depletion and amortization expense, exploration expense and share-based compensation expense, further adjusted to exclude the effects of non-cash changes in the fair value of derivatives, impairments, net gains and losses on the sale of assets, the non-cash portion of loss on the extinguishment of debt and other non-cash items. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income (loss) from continuing operations.

PENN VIRGINIA CORPORATION
GUIDANCE TABLE - unaudited
(dollars in millions except where noted)
We are providing the following guidance regarding financial and operational expectations for full-year 2011. These estimates are meant to provide guidance only and are subject to change as PVA's operating environment changes
		First				Second			Third
		Quarter				Quarter			Quarter			YTD			Previous Full-Year						Revised Full-Year						Changes in						Implied Fourth Quarter.
		2011				2011			2011			2011			2011 Guidance						2011 Guidance						2011 Guidance						2011 Guidance
Production:
Natural gas (Bcf)			9.7			8.9			8.1			26.6			34.0		-	35.0			33.9		-	34.0			(0.1	)	-	(1.0	)		7.3		-	7.4
Crude oil (MBbls)			188			219			427			833			1,450		-	1,600			1,475		-	1,525			25		-	(75	)		642		-	692
NGLs (MBbls)			220			253			222			695			950		-	1,050			875		-	900			(75	)	-	(150	)		180		-	205
Equivalent production (Bcfe)			12.2			11.7			11.9			35.8			48.5		-	50.5			48.0		-	48.5			(0.5	)	-	(2.0	)		12.2		-	12.7
Equivalent daily production (MMcfe per day)			135.2			128.6			129.9			131.2			132.9		-	138.4			131.5		-	132.9			(1.4	)	-	(5.5	)		132.4		-	137.9
Operating expenses:
Lease operating ($ per Mcfe)		$	0.84			0.92			0.71			0.82			0.80		-	0.85			0.80		-	0.82			0.00		-	(0.03	)		0.73		-	0.81
Gathering, processing and transportation costs ($ per Mcfe)		$	0.33			0.37			0.25			0.31			0.34		-	0.35			0.30		-	0.31			(0.04	)	-	(0.04	)		0.26		-	0.30
Production and ad valorem taxes (percent of oil and gas revenues)			7.5	%		3.9	%		4.1	%		5.1	%		5.0	%	-	6.0	%		5.0	%	-	5.5	%		0.0	%	-	(0.5	%)		5.0	%	-	5.5	%
General and administrative:
Recurring general and administrative		$	11.5			10.9			9.3			31.7			44.5		-	45.5			40.7		-	41.2			(3.8	)	-	(4.3	)		9.0		-	9.5
Share-based compensation		$	1.8			2.0			1.8			5.6			6.5		-	7.5			7.1		-	7.6			0.6		-	0.1			1.5		-	2.0
Restructuring		$	0.1			0.1			1.6			1.7			0.1		-	0.1			2.3		-	2.5			2.2		-	2.4			0.6		-	0.8
Total reported G&A		$	13.4			13.0			12.6			39.0			51.1		-	53.1			50.1		-	51.3			(1.0	)	-	(1.8	)		11.1		-	12.3
Exploration:
Dry hole costs		$	16.4			2.1			0.3			18.9			18.5		-	19.0			18.9		-	19.1			0.4		-	0.1			0.0		-	0.2
Unproved property amortization		$	10.6			12.0			11.0			33.6			45.0		-	47.0			44.6		-	45.1			(0.4	)	-	(1.9	)		11.0		-	11.5
Other		$	2.5			5.3			7.9			15.7			17.0		-	18.0			17.7		-	19.7			0.7		-	1.7			2.0		-	4.0
Total reported Exploration		$	29.5			19.4			19.3			68.2			80.5		-	84.0			81.2		-	83.9			0.7		-	(0.1	)		13.0		-	15.7
Depreciation, depletion and amortization ($ per Mcfe)		$	2.86			2.82			3.80			3.16			3.10		-	3.25			3.55		-	3.60			0.45		-	0.35			4.67		-	4.86
Capital expenditures:
Development drilling		$	36.8			82.9			88.2			207.9			253.0		-	263.0			302.9		-	307.9			49.9		-	44.9			95.0		-	100.0
Exploratory drilling		$	26.9			12.9			13.4			53.2			44.0		-	50.0			59.2		-	60.2			15.2		-	10.2			6.0		-	7.0
Pipeline, gathering, facilities		$	0.4			3.2			2.7			6.3			9.0		-	10.0			10.3		-	12.3			1.3		-	2.3			4.0		-	6.0
Seismic		$	1.8			4.3			2.9			9.0			8.0		-	9.0			10.0		-	11.0			2.0		-	2.0			1.0		-	2.0
Lease acquisitions, field projects and other		$	38.3			1.6			6.5			46.4			46.0		-	48.0			50.4		-	51.4			4.4		-	3.4			4.0		-	5.0
Total oil and gas capital expenditures		$	104.2			104.9			113.7			322.8			360.0		-	380.0			432.8		-	442.8			72.8		-	62.8			110.0		-	120.0
End of period debt outstanding		$	508.7			597.7			613.0			613.0
Effective interest rate			10.6	%		10.5	%		10.5	%		10.5	%
Income tax benefit rate			35.0	%		35.8	%		47.7	%		36.5	%

PENN VIRGINIA CORPORATION
GUIDANCE TABLE - unaudited - (continued)
Note to Guidance Table:
The following table shows our current derivative positions.
									Weighted Average Price
			Instrument Type			Average Volume Per Day			Floor/Swap			Ceiling
Natural gas:						(MMBtu)			($ / MMBtu)
Fourth quarter 2011			Costless collars			20,000			6.00			8.50
First quarter 2012			Costless collars			20,000			6.00			8.50
Fourth quarter 2011			Swaps			10,000			5.01
First quarter 2012			Swaps			10,000			5.10
Second quarter 2012			Swaps			20,000			5.31
Third quarter 2012			Swaps			20,000			5.31
Fourth quarter 2012			Swaps			10,000			5.10
Crude oil:						(barrels)			($ / barrel)
Fourth quarter 2011			Costless collars			360			80.00			103.30
First quarter 2012			Collars (a)			1,000			90.00			97.00
Second quarter 2012			Collars (a)			1,000			90.00			97.00
Third quarter 2012			Collars (a)			1,000			90.00			97.00
Fourth quarter 2012			Collars (a)			1,000			90.00			97.00
First quarter 2013			Collars (a)			1,000			90.00			100.00
Second quarter 2013			Collars (a)			1,000			90.00			100.00
Third quarter 2013			Collars (a)			1,000			90.00			100.00
Fourth quarter 2013			Collars (a)			1,000			90.00			100.00
Fourth quarter 2011			Swaps			500			109.00
First quarter 2012			Swaps (a)			500			100.00
Second quarter 2012			Swaps (a)			500			100.00
Third quarter 2012			Swaps (a)			500			100.00
Fourth quarter 2012			Swaps (a)			500			100.00

(a) Positions added in October 2011. A previous costless collar position for 500 barrels per day for calendar year 2012 at $100 x $120 per barrel was restructured as part of the consideration for the new positions. For the new collar positions, premiums of $7.63 per barrel in 2012 and $9.89 per barrel in 2013 will be paid as part of the net cash settlements during the applicable periods.

We estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, operating income for the fourth quarter of 2011 would increase or decrease by approximately $7.3 million. In addition, we estimate that for every $10.00 per barrel increase or decrease in the crude oil price, operating income for the fourth quarter of 2011 would increase or decrease by approximately $7.6 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at anticipated levels. These estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.